Fossil fuel combustion is increasing the atmospheric concentration of CO2 and causing concerns over global warming. The electric power generation industry is one of the largest CO2 emitters; roughly one third of the U.S. carbon emissions come from power plants. There is a need to find cost-effective ways to recover CO2 from the flue gases of existing power plants and other large point sources, for example refineries and cement plants.
There is also a need to remove CO2 from natural gas or biogas generated from anaerobic digesters to upgrade the methane concentration so that they can be used in a pipeline, to generate electricity or to run natural gas vehicles, for example.
The methods for post-combustion flue gas CO2 separation from existing power plants include chemical and physical solvent processes, chemical absorption and physical adsorption using solid sorbents, CO2 selective membranes and cryogenic separation. Chemical absorption using aqueous solutions of alkanolamines such as monoethanolamine (MEA) is a common CO2 separation method. However, amine absorption has large capital and operating costs. Large amounts of heat are needed to dissociate the CO2-amine complex via steam stripping during the regeneration step, resulting in very high energy consumption (Nsakala et al., 2001). The liquid phase contactors and circulation systems are also complex and expensive. Using conventional amine scrubbing to capture and purify CO2 from flue gas for sequestration could nearly double the cost of electricity and reduces the plant's output by 30% (Ramezan et al., 2007).
Chemical absorbents also suffer from poor efficiency because of the large heat input required to break a chemical bond to regenerate the sorbent. Physical adsorbents that bind the CO2 through a weaker interaction may help to reduce the regeneration energy input; however, the commercially available adsorbents have a number of drawbacks, including low capacity at the desired operating temperature, interference from water vapor and flue gas contaminants and poor cycle life.
Coal accounts for 56% of U.S. power generation and its contribution to future energy supply is expected to increase since U.S. has 25% of world's coal reserves (Tonks 2007). Coal-fueled Integrated Gasification Combined Cycle (IGCC) systems are environmentally superior to pulverized coal (PC)-fired boilers not only because they are more efficient at producing electricity, but also they can be equipped with more cost effective technologies for CO2 capture and pollution control.
In an IGCC, it makes sense to capture the CO2 early in the process (before the turbine), where it is concentrated and at high pressure, since it is far easier and less expensive to remove impurities when they are at high pressure and concentrated in the hot coal gas than when they are at atmospheric pressure and have been diluted by more 10:1 in the combustion turbine. The challenge for a CO2 sorbent is that it must have high capacities and more importantly high stability at temperatures in the range of 100-300° C. Typically amine modified sorbents are not stable under these conditions.
On-site or on-farm manure to energy conversion is a highly attractive option for managing animal manure (as well as other agricultural bio-waste). Animal manure is an energy-rich opportunity fuel with a heating value of 8,500 Btu/lb (on a dry ash free basis). Large farms and feedlot operations produce large quantities of manure in a small area. Anaerobic digester units capable of producing pipeline quality methane installed at each farm or dairy could be instrumental in eliminating the difficulties associated with the transport of manure off site. Further, they could be a source of heat and electricity, while significantly reducing disposal costs and operating expenses for the farms and feedlots. If consumed properly, use of manure-derived fuels can also protect against environmental problems such as groundwater leaching and greenhouse gas emissions (methane emissions) associated with land filling of the farm wastes. The use methane that would otherwise be emitted into the atmosphere is an untapped resource of energy that has a significantly greater global warming potential (GWP) than CO2. GWP is a measure of how much a given mass of greenhouse gas contributes to global warming over a specific time period compared to same mass of CO2 over the same period (GWP of Methane over 100 years is 25 while that of CO2 is 1).
The organic matter in the manure and other agricultural waste by-products can undergo a biological breakdown process in the absence of oxygen and be converted to “biogas”. Biogas is most commonly produced by anaerobic digestion or fermentation of biodegradable materials. Anaerobic digester units are widely accepted and used in farms, food processing facilities and dairies across the nation, and the biogas produced by them is commonly referred to as anaerobic digester gas or ADG. This type of biogas is similar to natural gas but is diluted with large amounts of CO2 (up to 45%), and therefore possesses less energy per unit volume than pipeline methane (natural gas). ADG is often used in a combined heat and power (CHP) gas engine to generate electricity and heat, which is used to meet the demands of the farm, dairy or food processing facility. The electricity demand varies greatly depending on the size of the facility and the nature of the process. Typically, energy requirements for a dairy farm range from 300-400 kWh per cow per year, to over 1500 KWh per cow per year depending on the type of barn used to house the cows, the type of lighting and cooling systems, the waste handling system, and the type of water heating (Ludington, 2004). However, anaerobic digestion of the manure collected per cow per year can produce up to 13,500 standard cubic feet (SCF) per year of methane (as biogas) with an energy content of 4,000 kWh. Frequently, the energy production capacity of the farm or feedlot is far greater than its total energy requirements. Hence, the excess energy or biogas or the manure (farm waste) needs to be exported. The most convenient and least capital intensive approach is to upgrade the biogas produced to “pipeline methane” specifications and put it into the natural gas distribution network where it can subsequently be used either for domestic heating or electricity generation.
Pressure swing and vacuum swing adsorption systems are useful for small to medium scale air separation to produce very high purity oxygen. These air separation systems use conventional physical adsorbents such as zeolites, carbon molecular sieves, activated carbons etc. Unfortunately, these sorbents are not suited for methane purification because they do not have the necessary selectivity for CO2 over H2O, and biogas is a humid gas. Hence, these sorbents are not suited for CO2 removal or for producing pipeline methane from biogas because they have a water adsorption capacity that is too large for high moisture applications. As a result there is a need for a CO2 sorbent with a high CO2 capacity and low water capacity to improve CO2 separations (for methane purification, for example).
U.S. Pat. No. 7,541,312 teaches a porous carbon characterized by a volumetric pore size distribution having two peaks, a first of said peaks being between 0.5 and 1.0 nm and a second of said peaks being between 1.0 and 5.0 nm. The porous carbon may have a volumetric capacitance in an organic electrolyte of at least 40 F/cm3, an average pore diameter between about 2 nm and about 30 nm, a surface area of at least 900 m2/g, and/or a density of at least 0.4 g/cm3. A method for making such a carbon includes a) curing a mixture comprising a carbohydrate, a dehydrating component, and a nonmetallic cationic pore-forming agent and b) carbonizing the cured carbon under conditions effective to provide a porous carbon having a surface area between about 100 m2/g and about 3000 m2/g. The dehydrating component and nonmetallic cationic component may comprise two moieties of one compound.
U.S. Pat. No. 7,288,136 teaches an improved method of treating an amine to increase the number of secondary amine groups and impregnating the amine in a porous solid support.
U.S. Pat. No. 3,491,031 teaches a method to create a CO2 sorbent by treating activated carbon with gaseous alcohol amines such as MEA. It utilizes a wet-chemical stripping method employing MEA to remove the adsorbed CO2 and regenerate the sorbent.
U.S. Pat. No. 6,547,854 teaches a method to create solid CO2 sorbents by the treatment of an acidified or basified solid substrate with a substituted amine salt.
U.S. Pat. No. 6,364,938 teaches a method to create CO2 sorbents by the incorporation of amine groups into a polymer substrate or backbone. The method is applicable to low load situations such as human breathing environments.
U.S. Pat. No. 5,876,488 teaches a method to create CO2 sorbents by dispersing aqueous amines in polymeric materials. Such sorbents are limited in application to human breathing environments and at ambient temperatures of 25° C.
U.S. Pat. Nos. 5,620,940, 5,492,683 and 5,376,614, teach methods to create CO2 sorbents by using amine-polyols on chemically inert supports. Sorbent desorption methods employ heat and/or reduced pressure.
U.S. Pat. No. 4,810,266 teaches a method to create CO2 sorbents by treating carbonized molecular sieves with alcohol amines.
All of these references contain at least one of the following limitations: low carbon capacity, high cost, temperature limitations, high heat inputs for regeneration, and high water sorption. For all of these applications, there is a need for a low cost sorbent that has high CO2 capacity, low water uptake (capacity or sorption), with long cyclic life and low energy input for regeneration (a low ΔH of adsorption).